AADE-17-NTCE-077 Proven Mud Motor Technology … · A Mud Motor with Embedded Sensors Provides...
Transcript of AADE-17-NTCE-077 Proven Mud Motor Technology … · A Mud Motor with Embedded Sensors Provides...
Copyright 2017, AADE
This paper was prepared for presentation at the 2017 AADE National Technical Conference and Exhibition held at the Hilton Houston North Hotel, Houston, Texas, April 11-12, 2017. This conference is sponsored by the American Association of Drilling Engineers. The information presented in this paper does not reflect any position, claim or endorsement made or implied by the American Association of Drilling Engineers, their officers or members. Questions concerning the content of this paper should be directed to the individual(s) listed as author(s) of this work.
Abstract Mud motors are the workhorse of our industry and are utilized on
almost every well drilled globally. This makes the mud motor the
perfect platform for drilling dynamics measurements at the bit and
bottom-hole assembly (BHA).
Proven mud motor technology has been upgraded with miniature
cost-effective embedded sensors to measure drilling dynamics at
the bit box and stator top sub. The sensors are sized to mount into
existing mud motor components without adding length or
compromising the mechanical integrity of the components.
The embedded sensors record shock, vibration, rotary speed,
toolface and temperature, which are the key dynamic elements to
understand downhole dysfunction and energy loss. Mounting the
sensors at either end of the mud motor provides two unique data
sets of dynamic measurements.
The embedded sensor mud motor enables downhole dynamics
mapping on every well drilled on a pad and across the field.
Mapping of drilling dynamics on every well provides an
understanding of problematic formations and parameters.
Systematic changes to bit, BHA and parameters over time
provides a clear picture of the right course of action to advance
performance toward the technical limit with the ultimate goal of
lowering drilling costs.
This paper will explain the mud motor embedded sensors and
measurements in detail. Examples of drilling dysfunction
recognized and mitigated from evaluation of the downhole
embedded measurements will be discussed. The overall
performance gains will be evaluated to demonstrate the value of
dynamic measurements onboard the mud motor.
Introduction Steerable drilling motors come in a number of different
varieties of lower end (bearing type and transmission) and bent
housings (fixed or adjustable and bit-to-bend length) [1]. Power
sections continue to evolve, with preference towards slow to
medium speed and high torque output [2]. Drilling dynamics
measurements were typically not commonplace embedded into
mechanical drilling tools until now.
The ability to record key drilling dynamics measurements at the
bit box and top sub of the motor (without increasing original
motor length, specifically the bit-to-bend length) enables
visibility of downhole motor performance. This advantage
gives the service company and operator a clear understanding
of drilling dynamics at the bit and BHA. Frequently the drilling
dynamics experienced at the bit is of higher magnitude than
what is recorded in the BHA (either via drilling dynamics
carrier subs or measurement-while-drilling [MWD] tools) [3].
With electronics and sensors becoming miniaturized, rugged
and cost-effective, this opens up a new generation of drilling
dynamics recorder packages that can be embedded into
steerable motors and drilling tools.
The sensors are designed to begin recording when the tool is
picked up to the rig floor, or sense rotation speed downhole to
enable data recording. This makes the embedded sensors
practically invisible to normal rig and drilling operations,
eliminating the need for specialist personnel on location and no-
added time to pick up the BHA [4].
Mud Motor with Embedded Sensors The latest generation of mud motor has been developed with
drilling dynamics sensors embedded into the bit box and top sub
as shown in Figure 1.
The sensors are installed into existing mud motors without
adding additional length, additional connections or
compromising the mechanical integrity of the motor.
Historically, measurements below the motor required an
additional sub between the lower motor connection and the bit
[5]. This increases the bit-to-bend length that changes the
characteristics of the motor (reduced build rates and different
rotary directional response), not to mention the increased side
loading applied to the radial bearings of the motor.
The alternative option is to use a bit with built-in sensors, but
these are limited to select bit manufacturers that have this
AADE-17-NTCE-077
Proven Mud Motor Technology Upgraded for the Digital Age –
A Mud Motor with Embedded Sensors Provides Cost-Effective Drilling Dynamics Measurements at Bit Box and Stator Top Sub Steve Jones and Junichi Sugiura, Scout Downhole / Sanvean Technologies
2 Steve Jones and Junichi Sugiura AADE-17-NTCE-077
capability [4,6-9].
Embedded Sensors The embedded sensors are designed to be compact enough to fit
into existing motor mandrel bit box and rotor catch top sub
without having to build new assets. The design allows for
modification of existing assets to accept the sensors.
Figure 2 shows the sensor installed in a 4 ¾” motor bit box
(although the package is designed to fit into 9 5/8” to 4 ¾”
motor sizes). Figure 3 shows the “puck” shaped sensor package
that is screwed into the motor bit box. Figure 4 shows the
sensor package installed into the rotor catch top sub and
retained with a hatch cover. Figure 5 shows the sensor pressure
barrel.
Both sensor designs contain the same electronics, solid-state
sensors and batteries. The shape of the package is the only
difference between the two sensors.
The sensor packages include onboard 3-axis inclinometers
(±16G), 3-axis shock sensors (±200G), 3-axis gyros and two
temperature sensors. The sensor records burst data to memory
every 5, 10, 20, 30, or 60 seconds. The sampling frequency (and
anti-aliasing filters) is programmable between 25Hz and
100Hz.
The downhole sensor package has a communication port for
set-up and memory dump at the motor service facility. Once the
sensors are set-up (e.g. at the repair and maintenance facility),
they autonomously start recording while tripping in and while
drilling. No interaction with the sensors is necessary at a well-
site, minimizing the cost of sensor deployment and making
them transparent to rig crews and on-site engineers.
Big Data Versus Small Data and Real-Time Versus Recorded Data Today big data analytics are widely experimented and practiced
in the oil and gas industry [10,11]. On the other hand, “small
data” is an amount of data small enough to make it informative
and easily accessible and manageable [12]. There is always
controversy in the drilling community regarding the best type
of data to be gathered downhole and whether this data should
be real-time or recorded.
Figure 6 shows the options available for drilling dynamics and
mechanics measurements. These can be tiered according to
level of service and price.
Doing nothing with downhole drilling measurements leads to
anecdotal and opinionated decisions. This is not the most
technical and efficient approach and can lead to a long learning
curve of trial, error and misinterpretation.
The other options range from basic drilling dynamic recorded
measurements (lowest cost) to drilling dynamics/mechanics
measurements real-time (highest cost). All these options will
cost more than simply doing nothing, so there has to be a
balance of expected results and performance gains from each
service.
The downhole datasets gathered with compact dynamics
recorders are “small data” which are well-structured and go
through well-established physics-based equations to be
converted to informative processed data, along with surface
data or electronic-drilling-recorder (EDR) data.
Proprietary software is used to merge downhole and surface
data and provides special visualization tools for data analysis.
The software also applies data analytics algorithms to convert
“small data” to actionable information as soon as surface and
downhole data are loaded into the software. This software and
workflow shorten the standard delivery time (several weeks) of
processed and actionable information within hours of tools
being returned to service base. Figure 7 shows the basic drilling
dynamics measurements recorded at the drilling motor.
Streaming real-time drilling dynamics data at high-speed data
rates requires supervision and interpretation by experienced
personnel while the well is being drilled. This real-time
monitoring and supervision processes can add significant cost
to a drilling project, not to mention the reliability of the real-
time system. The data is also analyzed post-run to provide
recommendations for the next well, adding post-run
interpretation and analysis costs as well.
Bear in mind that the complexity and cost of obtaining real-time
measurements close to the bit escalates the price significantly.
Real-time measurements close to the bit or in the BHA requires
wiring of components (or short-hop) [5,13]. Wiring through a
drilling motor and BHA adds complexity, reduces reliability
and increases overall cost. It may not be viable to run
sophisticated real-time measurements in the low-cost land
market environment.
To maintain operating costs as low as possible while having the
ability to run sensors in multiple locations on every well, the
only cost-viable solution is to run basic drilling dynamics
recorded measurements.
Time is Money – Fast Processing, Data Viewing and Mapping
Recording the valuable drilling dynamics information (small
data) that is easily merged with EDR (Electronic Drilling
Recorder) provides cost-effective information that can lead to
significant improvements in drilling practices and overall time
to drill the well.
Data is delivered to the operator as a data file-set that contains
downhole data merged with surface EDR. Proprietary software
is used to merge and display the data in easily read tracks and
traces.
Historically drilling dynamics logs are viewed in track and trace
AADE-17-NTCE-077 Proven Mud Motor Technology Upgraded for the Digital Age 3
format using PDF (Portable Document Format). This can make
it difficult to analyze the data as there is no freedom to zoom in
on areas of interest and change the track scales. The software
also allows the user to “read” the value of the curve when the
cursor is pointed. The proprietary software is available as a
“viewer” that enables the operator to change scales and zoom-
in on regions of interest. Data from other third-party devices
used in the BHA can be imported and used for full drilling
dynamics analysis.
One of the biggest complaints with handling drilling data sets
is the time and effort required to get the data into a usable
format for analysis. The proprietary “viewer” eliminates the
time spent configuring and merging data, thus reducing the time
required by the Drilling Engineer or Optimization Engineer.
The tailored viewing package makes data analysis much more
efficient.
Mapping the drilling dynamics data recorded from each well
drilled on a pad provides a roadmap of the best drilling practices
and downhole products utilized. This technique is cost-effective
and suitable for high-volume shale drilling development.
Software Viewer – Log Plot Figure 8 shows the software viewer display explaining the
main parameters that are displayed from a mud motor with
embedded sensors. Table 1 explains the mnemonics used on the
viewer.
This example data set is from a clean 8 ½” lateral run with no
drilling dysfunction.
Example #1 A 6 ¾” instrumented motor was used to drill an 8 ½” hole at
low angle. Figure 9 shows a snapshot of data and the associated
regions of interest, and causes are listed in Table 2.
From this example, there is a strong-intensity lateral frequency
signal of 8Hz at the motor top sub. This also aligns with an
increase in calculated revolutions per minute (RPM) at the
motor sub top indicating that whirl is likely present in the
motor/BHA. The lateral shocks at the motor bit box also
increase to high sustained values when this condition is present.
A closer look at the surface parameters indicates that the weight
on bit (WOB) was increased from 35Klbs to 40-45Klbs when
this downhole dysfunction was present. The onset of whirl in
the BHA resulted in lower rate of penetration (ROP) in this
particular case.
Sustained whirl for a long period of time increases the risk of
BHA failure and bit damage. Changes to WOB, surface RPM
settings and stabilization for subsequent runs/wells would allow
the data to be analyzed again to determine if the changes have
reduced the dysfunction and improved overall drilling
performance.
As can be seen from this example, small changes in surface
parameters can have a detrimental impact on downhole BHA
stability. These dysfunctions cannot be identified at surface.
However, the use of embedded sensors provides a clear picture
of the actual dysfunctional condition downhole. Small
systematic changes to parameters, BHA and bit can lead to a
more efficient drilling system and reduce overall drilling costs.
Example #2 Example #2 is from a 6 ¾” motor drilling an 8 ½” lateral
section. The case presented in Figure 10 is a snapshot of data
associated with regions of interest, and causes are listed in
Table 3.
This example sustains moderate levels of stick-slip (60%)
throughout the run. The stick-slip percentage is computed based
on the equation provided by Macpherson et al [14]. High levels
of lateral and axial shocks are observed at the bit box at the start
of the interval. These high levels of shock correlate with a
temperature rise at the bit box. A temperature rise of up to 36°C
(96.8°F) is noted between the bit box and top sub. The increase
in temperature at the bit box is sustained for the duration of the
high shocks.
Part way through the interval the WOB and flowrate are
increased. The high lateral and axial shocks at the bit remain
until the BHA is buried into new hole with the new parameters,
then the lateral and axial shocks at the bit return to low levels.
The reduction in shock at the bit box correlated with a reduction
in temperature at the bit box. Both temperature at the top sub
and bit box became the same.
The temperature rise at the bit was significant and sustained for
a long enough period of time that damage to the lower end of
the motor or lower end of the stator elastomer could have
resulted.
Changing WOB and flowrate had a positive effect in reducing
the shock experienced at the bit. ROP did not increase
significantly when the shock levels reduced, however the
reduced shock and elimination of temperature rise ultimately
helped preserve the bit and motor enabling a longer run.
This example clearly shows that parameter changes can have a
significant effect on the dynamics present at the bit. The high
shocks and temperature rise could not have been measured by a
sensor above the motor (i.e. MWD) and would have gone un-
noticed for the entire run.
Example #3 This case is taken from a 6 ¾” instrumented motor drilling an 8
½” lateral section. Figure 11 shows an example of data
associated with regions of interest, and causes are listed in
4 Steve Jones and Junichi Sugiura AADE-17-NTCE-077
Table 4
This data set is focused on a slide interval. The bit-box RPM
(from a gyro) is displayed as maximum and minimum values
from the burst data to closely evaluate RPM response.
It can be seen from the data that there are several hard motor
stalls indicated by a sudden increase in differential pressure. At
the same time the bit RPM reduced to zero and there was an
increase in lateral shock at the bit.
There are also multiple events where the RPM at bit reduced to
zero but there was no increase in differential pressure at surface
that would have indicated a motor stall downhole. Following
the stall the bit released and bit rotation speed increased up to
240 RPM. High sustained lateral shocks were present at the bit
during this interval.
No negative-RPM (reverse-rotation) events were noted
throughout the dysfunctional sections while slide drilling. Note
that negative-RPM events are common during a motor and/or
string stalls while rotary drilling [4].
This data set clearly shows a sequence of dysfunctional events
that would not be seen from sensors placed above the motor. It
is evident that weight transfer from surface to bit is inconsistent
due to the drag being experienced along the lateral. The use of
a friction-reduction tool (e.g. SPE-178792) placed in the correct
location would likely improve weight transfer and reduce bit
stalling and dysfunction at the bit [3].
Conclusions The application of embedded drilling dynamics sensors in a
mud motor bit box and top sub delivers a unique data set that
can identify dysfunction below and above the motor. The
dysfunction at the bit is not seen from sensors above the motor,
for example, from MWD.
The embedded drilling dynamics sensors have been designed to
be cost-effective (compared to drilling mechanic measurements
and real-time systems). This enables the sensors to be run on
every well to enhance the learning curve, rather than just
occasional wells where higher cost systems are typically used.
Running sensors embedded into the motor on every well
delivers a portfolio of data for comparison and optimization
purposes. Mapping of this data leads to a “smart landscape” of
drilling dynamics response to aid decision making and
ultimately reach the technical limit faster. Continuous
improvements can be executed well by well.
Delivery of downhole data merged with EDR utilizing a
proprietary viewer provides the Drilling Engineer and/or
Optimization Engineer with a data set that is immediately
usable. The ability to zoom-in on sections of data and change
track/trace scales enhances the data analysis experience and
time/effort required.
Acknowledgments The authors would like to thank Turbo Drill Industries, Scout
Downhole Inc. and Sanvean Technologies for their willingness
to publish the data obtained. We are grateful to the management
of Turbo Drill Industries, Scout Downhole Inc. and Sanvean
Technologies for permitting the publication of this work.
Nomenclature BHA = Bottom-Hole Assembly
DLS = Dogleg Severity (degrees per 100 feet)
DOC = Depth Of Cut
EDR = Electronic Drilling Recorder
GPM = Gallons Per Minute
MD = Measured Depth
MSE = Mechanical Specific Energy
MWD = Measurement While Drilling
PDC = Polycrystalline Diamond Compact
PDF = Portable Document Format
ROP = Drilling Rate Of Penetration
RPM = Revolutions Per Minute
TD = Target Depth
WOB = Weight On Bit
References
1. Samuel, R., Baldenko, D.F., and Baldenko, F.D. (2015). Positive
Displacement Motors – Theory and Applications.
Sigmaquadrant LLC. Houston, Texas, USA
2. BA, S., Pushkarev, M., Kolyshkin, A., Song, L., & Yin, L. L.
(2016, November 7). Positive Displacement Motor Modeling:
Skyrocketing the Way We Design, Select, and Operate Mud
Motors. Society of Petroleum Engineers. doi:10.2118/183298-
MS
3. Jones, S., Feddema, C., Sugiura, J., & Lightey, J. (2016, March
1). A New Friction Reduction Tool with Axial Oscillation
Increases Drilling Performance: Field-Testing with Multiple
Vibration Sensors in One Drill String. Society of Petroleum
Engineers. doi:10.2118/178792-MS
4. Jones, S and Sugiura, J. (2017, March 14). Drilling Dynamics
Data Recorders Now Cost-Effective for Every Operator -
Compact Embedded Sensors in Bit and BHA Capture Small
Data to Make the Right Decisions Fast. Society of Petroleum
Engineers. SPE-184738-MS
5. Wheeler, A. J., Billings, T., Rennie, A., Lee, R., Little, R.,
Huiszoon, C., & Boonen, P. (2012, June 16). The Introduction
Of An At-Bit Natural Gamma Ray Imaging Tool Reduces Risk
Associated With Real-Time Geosteering Decisions In Coalbed
Methane Horizontal Wells. Society of Petrophysicists and Well-
Log Analysts.
6. Leseultre, A., Lamine, E., & Jonsson, A. (1998, January 1). An
Instrumented Bit: A Necessary Step to the Intelligent BHA.
Society of Petroleum Engineers. doi:10.2118/39341-MS
7. Pastusek, P. E., Sullivan, E., & Harris, T. M. (2007, January 1).
Development and Utilization of a Bit Based Data Acquisition
System in Hard Rock PDC Applications. Society of Petroleum
Engineers. doi:10.2118/105017-MS
8. Rodriguez, J., Webb, T., Hale, P., et al., “Bit-Based Vibration
Tool Records Downhole Vibrations & Improves Drilling
AADE-17-NTCE-077 Proven Mud Motor Technology Upgraded for the Digital Age 5
Performance in Hard Carbonates,” presented at the 2015 AADE
National Technical Conference and Exhibition, San Antonio,
Texas, USA, April 8-9, 2015.
9. Sumrall, E.N., “Vibration Recording and System Signature Tools
for BHA Management” presented at the 2013 AADE National
Technical Conference and Exhibition, Oklahoma City, OK,
February 26-27, 2013.
10. Anand, P. (2013, April 1). Big Data Is a Big Deal. Society of
Petroleum Engineers. doi:10.2118/0413-0018-JPT.
11. Spath, J. (2014, January 1). Emerging Frontiers: Big Data!
Society of Petroleum Engineers. doi:10.2118/0114-0014-JPT.
12. Banafa, A. (2016, July 25). Small Data vs. Big Data: Back to the
Basics. OpenMind.
https://www.bbvaopenmind.com/en/small-data-vs-big-data-
back-to-the-basics/
13. Suh, A. “Innovative Instrumented Motor with Near-bit Gamma
and Inclination Improves Geosteering in Thin-bedded
Formations”, presented at the 2013 AADE National Technical
Conference and Exhibition, Oklahoma City, OK, February 26-
27, 2013.
14. Macpherson, J. D., Paul, P., Behounek, M., & Harmer, R. (2015,
September 28). A Framework for Transparency in Drilling
Mechanics and Dynamics Measurements. Society of Petroleum
Engineers. doi:10.2118/174874-MS
6 Steve Jones and Junichi Sugiura AADE-17-NTCE-077
Figure 1: Mud Motor with Embedded Sensors in Bit Box and Top Sub
Figure 2: Sensor Installed in Motor Bit Box
Figure 3: At-Bit Sensor Installed in a “Puck” Shaped Package
Figure 4: Top Sub Sensor Installed under Hatch Cover (Hatch Cover is Transparent to View Sensor)
Figure 5: Top Sub Sensor in Pressure Housing
AADE-17-NTCE-077 Proven Mud Motor Technology Upgraded for the Digital Age 7
Figure 6: Drilling Dynamics and Mechanics Landscape
Figure 7: Basic Drilling Dynamic Dysfunctions Measured at Embedded Sensors
8 Steve Jones and Junichi Sugiura AADE-17-NTCE-077
Figure 8: Software Viewer – Sample Data Set
Table 1: Software Viewer - Mnemonics Description
Track Trace Description
1 MSE Mechanical Specific Energy calculated using RPM measured at bit (kpsi)
1 Surface Block Height Surface block height from EDR (ft)
2 Surface Rotary RPM Surface rotary RPM from EDR (rpm)
2 28ft RPMraw Calculated RPM from sensor in motor top sub (rpm)
2 1.5ft GyroXmed Measured RPM at motor bit box (rpm)
3 Surface Weight on Bit Surface weight on bit from EDR (klbs)
3 Surface Rotary Torque Surface rotary torque from EDR (kft-lbs)
4 Surface Differential Pressure Surface differential pressure from EDR (psi)
4 Surface Total Pump Output Surface total pump output from EDR (gpm)
5 DOC (depth of cut) Calculated depth of cut (in/rev)
5 On Bottom ROP On bottom rate of penetration from EDR (ft/hr)
6 1.5ft StickSlip Stick-slip calculated at bit (%)
7 28ft ExtTemp Measured temperature at motor top sub (°C)
7 1.5ft ExtTemp Measured temperature at motor bit box (°C)
8 28ft ShYZpeak Peak lateral shock at motor top sub (g)
8 28ft ShXpeak Peak axial shock at motor top sub (g)
8 1.5ft ShYZpeak Peak lateral shock at motor bit box (g)
8 1.5ft ShXpeak Peak axial shock at motor bit box (g)
9 1.5ft VbXFftMag Axial frequency spectrum at motor bit box (Hz and Intensity)
10 1.5ft VbYZMag Lateral frequency spectrum at motor bit box (Hz and Intensity)
11 28ft VbXFftMag Axial frequency spectrum at motor top sub (Hz and Intensity)
12 28ft VbYZMag Lateral frequency spectrum at motor top sub (Hz and Intensity)
AADE-17-NTCE-077 Proven Mud Motor Technology Upgraded for the Digital Age 9
Figure 9: Example #1 – Whirl at Motor Top Sub, High Lateral Shock at Motor Bit Box
Table 2: Example #1 – Regions Identified and Cause
Region Identified Cause
1 Whirl at top sub seen on lateral frequency spectrum Intermittent spikes in lateral shock at bit up to 140g
Increased WOB from 35Klbs to 40Klbs
2
Wider band whirl at top sub seen on lateral frequency spectrum Whirl also seen at bit on lateral frequency spectrum
Sustaining 40g lateral shock at bit with spikes up to 170g Downhole RPM registering 30RPM above surface RPM
ROP slower than previously
Increased WOB to 42Klbs
3 Whirl indication at top sub disappears
Lateral shocks at bit reduce to less than 20g Reduced WOB to 35Klbs
Surface RPM increased briefly to 60 RPM
4
Whirl at top sub seen on lateral frequency spectrum Sustaining 40g lateral shocks at bit then sustaining 140g Downhole RPM registering 50RPM above surface RPM
ROP slower than previous parameters
Increased WOB to 40Klbs
10 Steve Jones and Junichi Sugiura AADE-17-NTCE-077
Figure 10: Example #2 – High Lateral/Axial Shocks at Bit Box and Associated Temperature Rise
Table 3: Example #2 – Regions Identified and Cause
Region Identified Cause
1 Wide band of RPM at bit box and top sub Unknown, sustained for majority of run
2 Averaging 60% stick-slip throughout run Unknown, sustained for majority of run
3 High sustained lateral and axial shocks at bit box, up to 200g
Corresponding temperature rise at bit box. Up to 36°C (96.8°F) difference in temperature between bit box and top sub.
WOB 14Klbs, Flowrate 440GPM
4 Lateral and axial shock at bit box returns to low levels. Temperature at
bit box and top sub return to the same values. Increased WOB to 18Klbs and increased
flowrate to 600GPM
AADE-17-NTCE-077 Proven Mud Motor Technology Upgraded for the Digital Age 11
Figure 11: Example #3 – Bit Stalling While Sliding
Table 4: Example #3 – Regions Identified and Cause
Region Identified Cause
1 Smooth sliding with no stick-slip or shock N/A
2
Onset of wider RPM spread (70-170 RPM). Wider RPM spread correlates with higher lateral shock at bit box (40g). Picked-up once
due to differential pressure increase (530 PSI), bit speed slowed to 30 RPM.
Surface WOB increased from 14Klbs to 19Klbs.
3 Hard motor stall. Differential pressure increased to 650 PSI. Bit RPM
goes to zero. Bit releases to 285 RPM. Lateral shock 52g. Surface WOB increased from 18Klbs to
25Klbs.
4 Multiple events of bit stalling to zero RPM. Sustained lateral shocks up
to 50g. No increase in differential pressure seen at surface. Erratic ROP during intervals when bit rotation zero. High stick-slip at bit.
Suspect inconsistent weight transfer to bit.